Downhole valve spanning a tool joint and methods of making and using same

ABSTRACT

A downhole valve is described. The downhole valve has a pilot valve section and a tool section. The pilot valve section has a first tube. The tool section has a second tube slidably coupled to the first tube of the pilot valve section so as to provide fluid communication between the pilot valve section and the tool section. The tool section can be in the form of a signal valve section of a mud pulse telemetry valve, a reamer, a vertical steerable tool, a rotary steerable tool, a by-pass valve, a packer, a whipstock, or stabilizer.

INCORPORATION BY REFERENCE

The present patent application claims priority to and incorporates byreference the entirety of the United States patent applicationidentified by U.S. Ser. No. 15/863,259, filed on Jan. 5, 2018, which isa continuation of U.S. Ser. No. 15/174,463, filed on Jun. 6, 2016, nowU.S. Pat. No. 9,863,197, and titled “Downhole Valve Spanning a ToolJoint and Methods of Making and Using Same.”

BACKGROUND

Integrating a mud pulse telemetry valve into a measuring while drilling(MWD)/logging while drilling (LWD) System is sometimes cumbersome andexpensive due the tight mechanical spacing tolerance requirements of thesystem components. Mechanical, electrical, and hydraulic connectionsmust be maintained.

Components of these systems are prone to mechanical wear because theyinclude moving parts that are placed directly in the drill string'sfluid flow path. The parts of this system are designed to generatepressure pulses so they purposely disrupt flow and are exposed to veryhigh velocity abrasive media. Additionally, in some designs,interchangeable components that disrupt the drilling fluid flow areconfigured for very specific drilling fluid flow rates. Occasionally,these configurations require adjustment at the rigsite.

Additionally, drill stem members, i.e., drill pipe and drill collars,that house or are a part of the mud pulse telemetry valve can includethreaded joints that can become damaged. The likelihood of thread damageis high because of the materials typically used in these devices and thelarge mass of these members which require heavy machinery to handle andtorque the members together. The damaged members sometimes requirereplacement. Sometimes, damaged threads can be re-machined (“cut back”)to restore their condition and extend the useful life of the veryexpensive drill stem member. This re-machining, however, changes thelength of the member and can inadvertently change the mechanical spacingbetween the system components of the mud pulse telemetry valve requiringthe replacement of the drill stem member.

Because of the tremendous investment already made in drill pipe anddrill collars, it is highly desirable that the mud pulse telemetry valvebe compatible with existing drilling equipment and require minimum or nomodification to the drill pipe and drill collars. Mud pulse telemetry isknown to offer an effective solution since it does not rely uponelectrical wiring extending to the surface, or other mechanisms whichmay necessitate modification to existing hardware. Mud pulse telemetrypropagates signals through the drilling fluid flowing in the drillstring to the surface at the speed of sound, thereby providing a veryfast communication link to the surface. Mud pulse telemetry is usuallyin the form of a valve located in the vicinity of the drilling bit,which intermittently restricts the flow of drilling fluid within thedrill string. The mud pulse telemetry system may be lowered on awireline located within the drill string, but is usually formed as anintegral part of a special drill collar inserted into the drill stringnear the drilling bit.

A continuous column of drilling fluid is circulating within the drillstring from the surface of the well to the drill bit at the bottom ofthe well during normal drilling operations. The basic operationalconcept of mud pulse telemetry is to intermittently restrict the flow ofdrilling fluid as it passes through the downhole telemetry valve,thereby creating a pressure pulse in the flow of the drilling fluid thattravels to the surface of the well at the speed of sound through thedrilling fluid. The information sensed in the vicinity of the drillingbit, which is to be transmitted to the surface, is encoded into adigital format and that digital formatted signal is used tointermittently actuate the downhole telemetry valve which restricts theflow of drilling fluid in the drill string, thereby transmitting pulsesto the surface. The pulses are detected at the surface and transformedinto electrical or other signals which can be decoded and processed toreveal transmitted information. In a typical oil or gas well, drillingfluid is circulated through the interior of the drill pipe at flow ratesof about 100 to about 1200 gallons per minute. The mud pulse telemetrysystem must operate to partially restrict this flow. Therefore, thesystem must control large amounts of energy. The downhole telemetryvalve must operate quickly to create a pressure pulse in this highpressure environment to intermittently restrict the flow of drillingfluid. This restriction must be sufficient to create a pressure rise inthe flow stream that will be detectable at the surface of the well. Atthe typically high flow rates of drilling fluid, considerable force andenergy are required to actuate the downhole telemetry valve in themanner necessary to create the desired pressure pulses.

Accordingly, there exists a need for a downhole valve capable ofeffectively transmitting downhole data or operating a downhole toolwhile reducing repair and maintenance costs. The inventive conceptsdisclosed herein are directed to such a downhole valve that, in someembodiments, can be characterized and/or used as a mud pulse telemetryvalve.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a partial sectional view of an exemplary downhole valvedeployed across a tool joint in accordance with the presently disclosedinventive concepts.

FIG. 2 is a partial sectional view of a pilot valve section of thedownhole valve of FIG. 1 in accordance with one embodiment of thepresently disclosed inventive concepts.

FIG. 3 is a partial sectional view of a signal valve section of thedownhole valve of FIG. 1 in accordance with one embodiment of thepresently disclosed inventive concepts.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

Before explaining at least one embodiment of the disclosure in detail,it is to be understood that the disclosure is not limited in itsapplication to the details of construction, experiments, exemplary data,and/or the arrangement of the components set forth in the followingdescription or illustrated in the drawings unless otherwise noted.

The systems and methods as described in the present disclosure arecapable of other embodiments or of being practiced or carried out invarious ways. Also, it is to be understood that the phraseology andterminology employed herein is for purposes of description, and shouldnot be regarded as limiting.

The following detailed description refers to the accompanying drawings.The same reference numbers in different drawings may identify the sameor similar elements.

As used in the description herein, the terms “comprises,” “comprising,”“includes,” “including,” “has,” “having,” or any other variationsthereof, are intended to cover a non-exclusive inclusion. For example,unless otherwise noted, a process, method, article, or apparatus thatcomprises a list of elements is not necessarily limited to only thoseelements, but may also include other elements not expressly listed orinherent to such process, method, article, or apparatus.

Further, unless expressly stated to the contrary, “or” refers to aninclusive and not to an exclusive “or”. For example, a condition A or Bis satisfied by one of the following: A is true (or present) and B isfalse (or not present), A is false (or not present) and B is true (orpresent), and both A and B are true (or present).

In addition, use of the “a” or “an” are employed to describe elementsand components of the embodiments herein. This is done merely forconvenience and to give a general sense of the inventive concept. Thisdescription should be read to include one or more, and the singular alsoincludes the plural unless it is obvious that it is meant otherwise.Further, use of the term “plurality” is meant to convey “more than one”unless expressly stated to the contrary.

As used herein, any reference to “one embodiment,” “an embodiment,”“some embodiments,” “one example,” “for example,” or “an example” meansthat a particular element, feature, structure or characteristicdescribed in connection with the embodiment is included in at least oneembodiment. The appearance of the phrase “in some embodiments” or “oneexample” in various places in the specification is not necessarily allreferring to the same embodiment, for example.

As used herein, the term “drilling fluid” or “drill fluid” refers tocirculating fluid used in rotational drilling to perform variousfunctions during drilling operations.

Referring now to the figures, and in particular to FIG. 1, shown thereinis an embodiment of an assembly 4 constructed in accordance with thepresent disclosure. The assembly 4 can be a part of a drill stem and/orbottom hole assembly and used as part of a drill string to drill a boreinto a subterranean formation. In general, the assembly 4 is providedwith a first tubular member 6, a second tubular member 8, and a downholevalve 10. The first tubular member 6 is provided with a first bore 12and a first end 14. The second tubular member 8 is provided with asecond bore 16 and a second end 18. The first end 14 of the firsttubular member 6 is connected to the second end 18 of the second tubularmember 8 to form a tool joint 20 such that the first bore 12communicates with the second bore 16. In the embodiment shown in FIG. 1,the first tubular member 6 is threadably connected to the second tubularmember 8 at the tool joint 20. In one embodiment, the first tubularmember 6 and the second tubular member 8 may be drill collars, forexample.

The downhole valve 10 is disposed within the first bore 12 and thesecond bore 16 so as to span the tool joint 20. In addition, thedownhole valve 10 is secured to the first tubular member 6 and thesecond tubular member 8.

The downhole valve 10 is provided with a pilot valve section 22 and atool section 24 connected by a slip joint 26.

In this embodiment, the tool section 24 includes a first tube 28, andthe pilot valve section 22 includes a second tube 30. The first tube 28of the tool section 24 extends beyond the confines of the second tubularmember 8 and across the tool joint 20 and is slidably connected to thesecond tube 30, which is recessed within the first tubular member 6, ofthe pilot valve section 22 to form the slip joint 26. However, it shouldbe understood that in some embodiments the first tube 28 can be recessedwithin the second tubular member 8 and the second tube 30 can extendbeyond the confines of the first tubular member 6 and across the tooljoint 20. Also, in some embodiments, the second tube 30 can be recessedwithin the first tube 28.

Slip joint 26 can be a fluid tight connection that allows rotational andlongitudinal movement between the pilot valve section 22 and the toolsection 24 while allowing pressurized drilling fluid in a first chamber32 formed in pilot valve section 22 to pass through a second chamber 34formed in the tool section 24. In some embodiments, the slip joint 26may not be completely fluid tight and may have an acceptable amount ofleakage.

Referring now to FIGS. 2 and 3, pilot valve section 22 is shown havingan actuator 40, an actuator housing 42, a screen 43, a pilot valvemember 44, a shaft 45, a pilot valve chamber 46, a pilot valve seatsection 48, fluid passageway 49, support fins 50, and the second tube30. Pilot valve section 22 may be secured in the first tubular member 6,for instance, via one or more set screw (not shown) threadablyconnecting one or more of the support fins 50 to the first tubularmember 6. In some embodiments, the support fins 50 may be sized anddimensioned to center the pilot valve section 22 within the firsttubular member 6. The actuator housing 42, screen 43, pilot valve seatsection 48, and support fins 50 may be secured to one another by meansknown in the art such as, for instance, threadable connections. Itshould be noted that in some embodiments, the support fins 50 may bepart of the first tubular member 6 and the actuator housing 42, screen43, and pilot valve seat section 48 may be secured to the support fins50 by means known in the art such as, for instance, at least one setscrew (not shown). Further, other methodologies can be used to securethe pilot valve section 22 within the first tubular member 6.

Pilot valve member 44 is threadably secured to one end of shaft 45 whichis connected to the actuator 40. When it is desired to move the pilotvalve member 44, the actuator 40 is energized and exerts a pushing orpulling force sufficient to push or pull the pilot valve member 44 intoa closed or open position.

Drilling fluid having a first pressure P1 passes through a plurality ofsmall openings in the screen 43 and into pilot valve chamber 46. Whenthe pilot valve member 44 is in the open position, at least a portion ofthe drilling fluid and/or pressure is communicated through fluidpassageway 49 which has a small diameter formed in one end of the pilotvalve seat section 48 and into the first chamber 32. After having passedthrough the fluid passageway 49, drilling fluid in the first chamber 32has a second pressure P2. As shown in FIG. 2, the fluid passageway 49may be substantially closed when the pilot valve member 44 at leastpartially interfaces with the pilot valve seat section 48. When pilotvalve member 44 interfaces with pilot valve seat section 48, drillingfluid flow into first chamber 32 is reduced.

As best shown in FIG. 3, the tool section 24 is provided with the firsttube 28, a spring 60, a piston 62, a flow plug 64, an orifice 66, apiston housing 90, a signal valve section seat 96, and at least one setscrew 98. In the embodiment shown, the tool section 24 is a signal valvesection of a mud pulse telemetry valve, however, it should be noted thatthe tool section 24 may be other types of drilling tools such as, forinstance, a reamer, a vertical steerable tool, a rotary steerable tool,a by-pass valve, a packer, a whipstock, or stabilizer.

When pilot valve member 44 is in the closed position, the limitedpressurized drilling fluid flowing into first chamber 32 does not exertsufficient pressure on an upper end 58 of the piston 62 to extend spring60 and hold a flow plug 64 (sometimes referred to as a poppet) of piston62 in engagement with orifice 66 which allows drilling fluid to flowaround the flow plug 64 of the piston 62 and through orifice 66. Inother words, the decrease in pressure causes a differential pressureacross flow plug 64, i.e. low pressure on the uphole facing end of flowplug 64 and high pressure on the downhole facing surface of flow plug64. This action provides flow plug 64 with the necessary pressurecondition to begin retracting from orifice 66 until an equilibriumpressure measured across flow plug 64 is achieved. When pilot valvemember 44 is in the open position, pressurized drilling fluid flows intothe first chamber 32 and onto the upper end 58 of piston 62 adding theneeded partial pressure bias to force spring 60 to extend and urgepiston 62 downwardly, thereby moving flow plug 64 downward to at leastpartially engage with orifice 66.

Although specific examples of the downhole valve 10 are shown anddescribed above, it should be understood that the tool section 24 andthe pilot valve section 22 can be implemented in other manners so longas one or more slip joint 26 hydraulically connects the tool section 24to the pilot valve section 22.

As shown in FIG. 3, the first tube 28 forms a generally tubularstructure having a substantially circular cross section and is providedwith at least one seal 70, an outer surface 72, and an inner surface 74.

As shown in FIG. 2, the second tube 30 forms a generally tubularstructure having a substantially circular cross section and is providedhaving an inner surface 80 and an outer surface 82.

When first tubular member 6 and second tubular member 8 are connected attool joint 20, the outer surface 72 of the first tube 28 is at leastpartially concentrically surrounded by the inner surface 80 of thesecond tube 30 to form the slip joint 26. To facilitate a fluid tightseal of the slip joint 26, the at least one seal 70 of the first tube 28at least partially interfaces with the inner surface 80 of the secondtube 30. It should be noted that in some embodiments, the slip joint 26does not require a fluid tight seal and a the slip joint 26 mayincorporate a seal-less joint so long as sufficient pressure ismaintained within the slip joint 26 to operate the tool section 24.

As explained above, it is common in the drilling industry for drill pipesuch as first tubular member 6 and second tubular member 8 to be damagedduring the drilling process. One area of common damage is the tool joint20. When the tool joint 20 is damaged, the tool joint 20 must bere-tooled, for instance, by machining to ensure a secure connection.Machining removes material from one or both of the first tubular member6 or second tubular member 8 which changes the relative distance and/orrelative orientation between the pilot valve section 22 and the toolsection 24. Because of the circular shape of the first tube 28 and thesecond tube 30 that together form the slip joint 26, the pilot valvesection 22 and the tool section 24 are not required to be oriented inany specific relation to one another. In other words, the downhole valve10 only requires that the pilot valve section 22 and the tool section 24be substantially aligned along axis X.

In addition, slip joint 26 allows the relative distance between thepilot valve section 22 and the tool section 24 to be adjustedlongitudinally along axis X. For instance, damage to the first tubularmember 6 and/or the second tubular member 8 at the tool joint 20 mayrequire re-cutting of threads and/or shoulders which would shorten thefirst tubular member 6 and/or the second tubular member 8. The slipjoint 26 allows such repairs to be made without requiring re-tooling tore-insert the downhole valve 10 because the change in length andrelative orientation can be absorbed by the slip joint 26.

The slip joint 26 allows longitudinal adjustment between the pilot valvesection 22 and the tool section 24 as long as sufficient differentialpressure across the downhole valve 10 is maintained to actuate the toolsection 24 despite pressure changes caused by changes in a length L1(FIG. 1) of the slip joint 26. In the present example, the length L1 ofthe slip joint 26 must be maintained such that pressure P2 of thedrilling fluid across the upper end 58 of the piston 62 is sufficient toextend spring 60 and hold the flow plug 64 of piston 62 in engagementwith orifice 66 when the pilot valve member 44 is in the open position.A maximum length of the slip joint 26 is limited by pressure losses andthe required tool actuation pressure. A minimum length of the slip joint26 is dictated by the length of engagement of the tool joint 20 anddesired tool joint cutbacks that would want to be absorbed or adjustedfor.

In some embodiments of the downhole valve 10, the first tube 28 and thesecond tube 30 may be designed to permit misalignment. For example, atleast a portion of the first tube 28 and the second tube 30 may beconstructed of a flexible material (e.g., steel) having sufficientdurability to withstand the downhole environment. In another embodiment,a mechanical joint (not shown) may be inserted in the first tube 28and/or the second tube 30 that absorbs misalignment.

As best shown in FIG. 3, the first tube 28 may be removeably secured tothe piston housing 90. In some embodiments, the piston housing 90 alsoserves to secure the spring 60 and act as a linear guide for the piston62.

In the embodiment shown in FIG. 3, the piston housing 90 is removeablysecured to the signal valve section seat 96. The signal valve sectionseat 96 is secured in second tubular member 8, for instance, using atleast one set screw 98 or other securing means. In some embodiments, tofacilitate a secure connection, the second tubular member 8 may beprovided having a shoulder 100 on which the signal valve section seat 96rests.

As will be understood by one skilled in the art, the presently disclosedassembly 4 can be assembled at one location such as, for instance, awellsite. Alternately, the assembly 4 can be at least partiallyassembled at a first location, such as a service center or lab, and thencompletely assembled at a second location, such as a wellsite. Forexample, the pilot valve section 22 of the downhole valve 10 can bepositioned and secured in the first bore 12 of the first tubular member6 adjacent to the first end 14 of the first tubular member 6 at thefirst location. Similarly, the tool section 24 of the downhole valve 10can be positioned and then secured in the second bore 16 of the secondtubular member 8 adjacent to the second end 18 of the second tubularmember 8. In this embodiment, the first tube 28 of the tool section 24extends beyond the confines of the second tubular member 8.

Once the pilot valve section 22 has been secured to the first tubularmember 6, and the tool section 24 has been secured to the second tubularmember 8, the first and second tubular members 6 and 8 can betransported to the second location, such as the wellsite, and be used toform a portion of the drill stem.

For example, the first end 14 of the first tubular member 6 can beconnected to the second end 18 of the second tubular member 8 to formthe tool joint 20 thereby also fluidly connecting the pilot valvesection 22 of the downhole valve 10 disposed within the first tubularmember 6 to the tool section 24 of the downhole valve 10 disposed withinthe first tube 28.

The modular nature of the downhole valve 10 allows interchange ofcomponents, for instance, due to wear, damage, or alternateconfigurations, i.e. the flow plug 64 and orifice 66 size combinationsmay be adjusted for specific fluid weights/densities and flow rates toensure appropriate pressure pulse amplitudes.

While the actuator 40 is described herein as a linear actuator, itshould be noted that in some embodiments, the actuator 40 may use othermethods such as, for instance rotation to move the pilot valve member 44between the open and closed position.

Although the downhole valve 10 described herein produces positivepressure pulses by blocking the flow of the drilling fluid, it should benoted that the downhole valve 10 can be designed and configured in otherways. For instance, in another embodiment (not shown) the downhole valve10 may produce a negative pulse by opening up a passage (not shown)which allows temporary communication between the drilling fluid insidethe first tubular member 6 and/or the second tubular member 8 anddrilling fluid returning to the surface. In some embodiments, thedownhole valve 10 can produce both positive and negative pulses byrelying on both types of operations, i.e., constricting a passage forthe flow of fluid as well as opening up a passage for the flow of fluid.

The tool section 24 of the downhole valve 10 has been shown anddescribed herein as a signal valve section, which, together with thepilot valve section 22 forms a mud pulse telemetry valve wherein linearactuation of the pilot valve member 44 creates a differential pressurein the second tube 30 which is communicated through the first tube 28and causes the piston 62 to move between an open and a closed position.However, it should be understood that in other embodiments, the toolsection 24 may be provided with a different tool (not shown) such as,for instance, a reamer, a vertical steerable tool, a rotary steerabletool, a bypass valve, a packer, a whipstock, or a stabilizer, that maybe actuated or controlled by creating the pressure differential asdescribed herein. In other words, the inventive concepts disclosedherein are adapted to communicate a pressure differential or pressurepulse across the slip joint 26 to engage different tools that may beoperated by pressure differential or pressure pulse. In suchembodiments, the pilot valve section 22 would operate in accordance withthe concepts disclosed herein to create the pressure differential orpressure pulse which would be communicated from the second tube 30through the first tube 28 which would be associated with the differenttool.

From the above description, it is clear that the inventive conceptsdisclosed herein are well adapted to carry out the objects and to attainthe advantages mentioned herein as well as those inherent in theinventive concepts disclosed herein. While presently preferredembodiments of the inventive concepts disclosed herein have beendescribed for purposes of this disclosure, it will be understood thatnumerous changes may be made which will readily suggest themselves tothose skilled in the art and which are accomplished within the scope andcoverage of the inventive concepts disclosed and claimed herein.

What is claimed is:
 1. An assembly, comprising: a first tubular memberhaving a first bore and a first end; a second tubular member having asecond bore and a second end, the first end of the first tubular memberconnected to the second end of the second tubular member to form a tooljoint; and a downhole valve disposed within the first bore and thesecond bore so as to span the tool joint, the downhole valve having apilot valve section secured to the first tubular member and a toolsection secured to the second tubular member, the pilot valve sectionand the tool section fluidly communicating through a slip joint formedwhen the first tubular member is coupled to the second tubular member,the slip joint configured to form a fluid tight connection allowing forrotational and longitudinal movement between the pilot valve section andthe tool section, the pilot valve section including a pilot valve havinga pilot valve member configured to be connected to an actuator toselectively move the pilot valve member into a closed or open position;wherein the downhole valve is a mud pulse telemetry valve, and the toolsection is a signal valve section of the mud pulse telemetry valve. 2.The assembly of claim 1, wherein the pilot valve section includes afirst tube, and the tool section includes a second tube coupled to thefirst tube, at least one of the first and second tube extending acrossthe tool joint and forming the slip joint.
 3. The assembly of claim 2,wherein the first tube and the second tube are slidably coupled.
 4. Adownhole valve, comprising: a pilot valve section having a first tube influid communication with a pilot valve, the pilot valve provided with apilot valve member configured to be connected to an actuator toselectively move the pilot valve member into a closed or open positionfor providing a differential pressure or fluid flow through the firsttube; a tool section having a tool and a second tube, the second tubeslidably coupled to the first tube of the pilot valve section to form aslip joint separate from the tool so as to provide fluid communicationbetween the pilot valve section and the tool section, the tool operableby differential pressure or fluid flow ported through the first andsecond tubes; wherein the pilot valve section is secured within a firstbore of a first tubular member and the tool section is secured within asecond bore of a second tubular member, wherein the slip joint is formedby coupling the first tubular member to the second tubular member, theslip joint being disposed within one of the first tubular member and thesecond tubular member and configured to form a fluid tight connectionallowing for rotational and longitudinal movement between the pilotvalve section and the tool section; wherein the downhole valve is a mudpulse telemetry valve, and the tool section is a signal valve section ofthe mud pulse telemetry valve.
 5. A method for assembling a downholevalve, comprising: connecting a first tubular member having a first boreand a first end to a second end of a second tubular member having asecond bore thereby fluidly connecting, via a slip joint, a pilot valvesection of the downhole valve secured within the first tubular member toa tool section of the downhole valve secured within the second tubularmember, the slip joint being disposed within one of the first tubularmember and the second tubular member and configured to form a fluidtight connection allowing for rotational and longitudinal movementbetween the pilot valve section and the tool section, the pilot valvesection provided with a pilot valve having a pilot valve memberconfigured to be connected to an actuator to selectively move the pilotvalve member into a closed or open position for providing a differentialpressure or fluid flow through the slip joint, wherein a tool of thetool section is operable by the differential pressure or fluid flow fromthe pilot valve section through the slip joint; wherein the downholevalve is a mud pulse telemetry valve, and the tool section is a signalvalve section of the mud pulse telemetry valve.
 6. The method of claim5, wherein the first end and the second end are threaded, and whereinconnecting the first end to the second end is defined further asrotating one of the first tubular member and the second tubular memberrelative to the other one of the first tubular member and the secondtubular member to threadably couple the first and second ends andsimultaneously rotating at least a portion of the slip joint.
 7. Amethod, comprising: securing a pilot valve section of a downhole valvein a first bore of a first tubular member adjacent to a first end of thefirst tubular member, the pilot valve section provided with a pilotvalve having a pilot valve member configured to be connected to anactuator to selectively move the pilot valve member into a closed oropen position for providing a differential pressure or fluid flow; andsecuring a tool section of the downhole valve in a second bore of asecond tubular member adjacent to a second end of the second tubularmember, at least one of the pilot valve section and the tool sectionhaving a tube extending beyond confines of the respective first tubularmember and the second tubular member, the tube fluidly connecting thepilot valve section and the tool section such that the tool section isoperable by differential pressure or fluid flow ported through the tube,wherein the tube is a first tube, and the other one of the pilot valvesection and the tool section has a second tube, and further comprisingconnecting the first end of the first tubular member to the second endof the second tubular member to form a tool joint disposed within one ofthe first tubular member and the second tubular member, thereby alsofluidly connecting the pilot valve section of the downhole valvedisposed within the first tubular member to the tool section of thedownhole valve with the first tube and the second tube; wherein thedownhole valve is a mud pulse telemetry valve, and the tool section is asignal valve section of the mud pulse telemetry valve.
 8. The method ofclaim 7, wherein the steps of securing the pilot valve section and thetool section are performed at a first location, and the step ofconnecting the first end of the first tubular member to the second endof the second tubular member is performed at a second location remotefrom the first location.
 9. The method of claim 7, wherein the secondlocation is a well-site.